It is necessary in many applications to obtain an indication of the water content of a hydrocarbon liquid and water mixture such as a petroleum and water mixture. For example, pipeline operators will ordinarily wish to ensure that the oil carried by such pipelines has a water content which does not exceed a certain value. This is so because the pipeline companies wish to ensure they are not purchasing water and paying for oil. This is also so because water can corrode the pipeline which can result in premature pipeline failure. Water can also freeze in the pipeline and block flow. This has the potential to close the pipeline and shut in the oil being carried by the pipeline.
The maximum amount of water generally allowed in oil carried by a pipeline is 0.5% of the gross volume of the oil. In the event such a percentage is exceeded, the producer may be refused access to the pipeline or penalised accordingly.
Similarly, oil producers have reasons for ensuring they too have information concerning the water content of the oil which they have produced. First, they may wish to corroborate the water content figures obtained by the pipeline operator. Second, they may wish to monitor performance of their water removal equipment and, third, they may wish to optimize their water removal processes and equipment so that they meet the standards required by the pipeline operator but do not substantially exceed them which can be more profitable for their operations.
Several previous instruments have been used to measure the water content of a liquid hydrocarbon and water mixture but each suffers from various disadvantages. Such instruments include the net oil coriolis meter type instrument which does not have sufficient accuracy for measuring small amounts of water because it depends on the accuracy of mass, density and temperature measurements. It likewise depends on the hydrocarbon and water densities remaining constant during operation and that such densities be established prior to the initiation of operation of the device. The errors in the readings obtained by net oil coriolis meter devices can be in the order of 0.5% water, which errors are in the range or even greater than the amount of water in the oil-water mixture which is permitted by the pipeline operator.
Further instruments used in the measurement of water content in an oil-water mixture include the cut monitor or basal sediment and water ("BS & W") type instrument which utilises capacitance to determine the volume of water in the oil. Such instruments are far more accurate than the coriolis type instruments for measuring small percentages of water but they too depend on the density of the hydrocarbon mixture and temperature remaining constant although some such instruments do utilise temperature compensation.
Manual sampling is also used but it suffers from clear disadvantages, perhaps the greatest of which is that it is not a continuous sampling on-line technique. Automatic sampling gives an average rather than an instantaneous water cut. Both manual and automatic sampling require that the sample obtained of the oil and water mixture be a representative sample.
Instruments known as temperature compensated basal sediment and water ("BS & W") monitors are also utilised. A resistance temperature device ("RTD") is used with the BS & W instrument. The RTD is inserted in and measures the temperature of the fluid stream. It calculates the corrected water content using a linear relationship between the temperature and the dielectric constant of the oil. In addition to the measurement of the water content for a mixture of specific density, the instrument allows four(4) different mixture densities to be measured by utilising a linear relationship between the capacitance and the water content. However, it also suffers limitations in that the density of the mixture must be known prior to the startup of the apparatus and it is assumed that the density is constant over time which may not be correct. The four(4) densities must be close to each other for good accuracy and an external switch is required to select the calibrated density closest to that of the mixture being tested. However, errors still arise when the density of the mixture differs from the densities for which the apparatus is calibrated.
To improve the correlation between the capacitance measurement of the liquid hydrocarbon and water mixture obtained by the BS & W monitor and the corresponding value for water content percentage of the mixture being measured, it is noted that errors can arise. For example, if the liquid hydrocarbon and water mixture is inserted into a capacitance measuring device and the capacitance measurement obtained is "Y1", the percentage water content of the mixture "X1" is directly obtained from the linear relationship shown therein.
However, if the density of a second sample of liquid hydrocarbon changes from the density of the first sample of liquid hydrocarbon being measured with reference to FIG. 3 as would be the case, for example, where oil from a different field is being sampled and even though the water content may be precisely the same in the second sample, the capacitance can and will change to, say, "Y2". Correlating the capacitance value of "Y2" to the water content value will give an erroneous reading of "X2".
Techniques have been adapted in an attempt to minimize the erroneous readings. For example, different sets for capacitance tables can be generated depending on the density of the liquid hydrocarbon intended to be carried. Again with reference to FIG. 3, a second sample of known density will result in a capacitance reading of "Y2" and in correlating this value to water content, it will be found that the correct value of "x1" will be obtained assuming that the two samples are as described above; that is, that the two samples have the same water content. This technique, however, is clearly disadvantageous when the density of the liquid hydrocarbon-water mixture changes unbeknownst to the operators.
In capacitance type instruments such as cut monitor instruments, three variables effect the capacitance reading, namely the area of the plates between which the capacitance is taken, the distance between the plates and the dielectric constant of the material between, the plates. Since the area of the plates and the distance between them can be held constant by the layout of the instrumentation, the only remaining factor affecting capacitance is the dielectric constant of the material being measured between the plates.
The dielectric constant for petroleum changes depending upon the density of the oil and the temperature of the oil. As the density of the oil increases, the dielectric constant increases and as the density decreases, the dielectric constant decreases. Likewise, as the temperature of the oil increases, the density decreases and the dielectric constant therefore decreases.
Since the dielectric constant for oil is approximately 2.0, depending upon its density and the dielectric constant for water is approximately 80, as the water content of the oil increases, the dielectric constant will also increase.
However, while some previous instruments have provided compensation for dielectric changes due to temperature changes and while some instruments have provided for manual calibration of the instrument depending on the density of the oil and water mixture carried by the pipeline, none have provided on-line compensation for dielectric changes due to density changes in the oil-water mixture which results by differing oil compositions. This is clearly disadvantageous since the product being carried by the pipeline may change significantly over time thereby resulting in incorrect readings for the water content of the oil.
A further problem which produced incorrect readings for the instrument resulted from the previously incorrect understanding that the capacitance of the oil was directly proportional to the density. In fact, it has been found that the relationship is non-linear with the result that the oil dielectric constant can be more accurately determined than previously.
Yet a further problem is set forth herein to assist a full understanding of the invention. This problem relates to the dual effect of dielectric constant changes due to changes in density and temperature. It was previously thought that two compensations were needed to obtain capacitance, namely that compensation due to temperature change and that compensation due to density change. However, it has been found that temperature compensation need not be performed for the instrument of the present invention. Rather, as the density changes in the oil-water mixture and as the dielectric constant likewise changes as a result of such density changes, it appears that temperature compensation itself need not be performed. It is emphasized that, at the present time, not enough is known about this phenomena to ensure that the statements made herein are correct without qualification but, based upon results to date, it does appear as if such temperature compensation need not be made.